Within the oil and gas industry, the continuing search for and exploitation of oil and gas reservoirs has resulted in the development of directionally drilled boreholes, that is boreholes which extend away from vertical and which permit the borehole to extend into the reservoir to a greater extent than with conventional vertical well boreholes. This type of well borehole is often referred to as an Extended Reach Development well or “ERD” well and in many cases the well borehole is drilled at a high angle from vertical or horizontally for a considerable distance.
In order to transmit mechanical power downhole for the drilling process, or to prevent deferential sticking, it is typically necessary to manipulate drilling tubulars from surface, either by rotating the drill string from surface and/or by transmitting weight from the tubulars in the more vertical section of the wellbore to the drill bit at the bottom.
However, it will be recognised that in high angle or horizontal wellbores, the majority of the tubulars of the string will be lying on the low side of the borehole with their weight acting on the borehole wall. This generates considerable cumulative friction when the tubulars are manipulated from surface; this taking the form of torsional or rotational friction in the case where the tubulars are rotated. Torsional or rotational friction therefore becomes a significant limiting factor in the length of high angle and horizontal borehole that can be achieved in any given size of hole.
The main factor that contributes to this limitation is cumulative torque, which can be calculated from the vertical cumulative weight of the tubulars in the high angle and/or horizontal section multiplied by the friction coefficient (normally taken at between 0.2 and 0.3 for cased and open borehole respectively) multiplied by the radius at which borehole contact is made. By way of example, 10,000 ft. of drilling tubular in open borehole with an average vertical weight component of 26 lbs per linear ft. acting at a contact radius of 3.39 inches with a friction coefficient of 0.3 would generate a cumulative torque of 10,000×26×(3.39 divided by 12)×0.3=22,035 ft./lbf. At an average drilling rotational speed of 150 rpm this would result in the loss of approximately 100 horsepower in frictional losses.
This frictional loss will increase as a function of borehole length and will eventually reach a point where the mechanical power input at surface is totally consumed before it reaches the bottom of the borehole and the drilling process will cease to be possible well before this point is reached.
Additionally and perhaps more importantly, as the torsional friction losses increase so will the torsional input requirement at surface to the point where the threaded connections in the jointed drilling tubulars reaches a point approaching their makeup torque. Continuing to drill beyond this borehole distance therefore risks potential torsional failure or twist off of the drilling tubulars.
There are a number of downhole tools currently in use in the oil industry which seek to address friction loss and reduce the frictional coefficient of the rubbing contact of rotating tubulars lying on the low side of the borehole. Conventional tools generally consist of a non-rotating bearing sleeve mounted on the body of the drilling tubulars or mounted on a sub-based tool installed between the threaded connections of the drilling tubulars. However, there are a number of problems associated with these conventional types of non-rotating bearing sleeves. For example, there are problems associated the methods of fixture of non-rotating sleeve and bearings to the body of the tubulars; with the use of split sleeves and clamping mechanisms; bearing life limitations due to aggressive nature of drilling mud; sealed versus non-sealed bearings; cuttings debris tolerance; with the possibility of loss in hole of component parts in operation; and with temperature ratings of conventional bearings and seals.